The present invention relates to a process for oil recovery, especially by tenside flooding and/or micellar polymer flooding in medium-salinity to higher-salinity reservoirs.
In the extraction of oil from reservoir rock formations, generally only a fraction of the originally present oil is successfully transported by means of primary recovery processes. In this procedure, the oil passes to the surface by means of the natural reservoir pressure. In secondary oil recovery, water is usually injected into one or several injection wells of the formation, and the oil is driven to one or several production wells and then brought to the surface. This so-called waterflooding as a secondary measure is relatively inexpensive and correspondingly is utilized frequently, but it produces in many cases only a slight additional oil extraction from the reservoir.
An effective displacement of the oil, more expensive but required for national economic purposes in view of future oil shortages, is accomplished by tertiary measures. These include processes wherein either the viscosity of the oil is lowered and/or the viscosity of the subsequent flooding water is raised and/or the interfacial surface tension between water and oil is reduced.
Most of these processes can be classified either as solution or mixture flooding, thermal oil recovery methods, tenside or polymer flooding and/or as a combination of several of these processes. Thermal recovery methods include injection of steam or hot water or they take place as subterranean combustion. Solution or mixture processes involve injecting a solvent for petroleum into the reservoir; this solvent can be a gas and/or a liquid.
Tenside processes are based primarily on an extensive lowering of interfacial tension between oil and flooding water. A distinction is made, depending on tenside concentration and in some cases type of tenside and additives, among tenside-supported waterflooding, usual tenside flooding (low-tension flooding), micellar flooding, and emulsion flooding. Furthermore, wettability of the rock surface as well as the mobility conditions are of great importance. Favorable mobility relationships between oil and water are attained by polymers.
Quite particularly, this invention concerns problems in processes for reservoirs governed by strong temperature fluctuations or by a temperature gradient. Since the temperature of reservoir rock formations is determined essentially by the thermal flow from the interior of the earth into the surface region, fluctuating temperatures are due either to strong inclinations of the reservoir or to interference with natural events. The latter includes, for example, the injection of water during waterflooding.
Waterflowing of long duration, especially when conducted on high-temperature reservoirs, ordinarily leads to the formation of a strong temperature gradient. This is especially pronounced in high-temperature offshore reservoirs flooded with cold seawater, resulting in strong cooling even of the more remote injection zones. Thus, for example in reservoirs in the North Sea region, temperature spans have been known to exist of between about 10.degree. C. close to the injection probes and about 100.degree. C. in more remote areas. However, the tenside flooding method utilized in each case is to be optimally effective, if at all possible, within the entire temperature range. This, of course, pre-supposes that the tenside remains stable for a long period of time under reservoir conditions.
Another problem of tenside flooding is that most of the tensides suitable for this purpose, such as, for example, alkyl-, alkylaryl- or petroleum sulfonates, have a very low tolerance limit with respect to the salinity of the reservoir waters. Even salt concentrations of merely 1,000 ppm are often deemed problematic, the sensitivity of these tensides against alkaline earth ions being especially pronounced. The upper critical limit concentration of salinity is given as 500 ppm in U.S. Pat. No. 4,110,228. In the presence of high salt concentrations, precipitation products in the form of insoluble salts are created when using the aforementioned tensides. As a result, on the one hand, material needed for the desirable surfactant action along the water-oil interface is lost; on the other hand, the precipitation products can lead to plugging of the formation. As is known, many reservoir waters contain substantially higher salinities; a very considerable portion of the light oil deposits in North America have salinities around 100,000 ppm and higher, the content of dissolved alkaline earth ions being considerable in most cases. Also, the seawater frequently injected for secondary measures in offshore reservoirs exhibits, with a TDS value of about 36,000 ppm and alkaline earth ion concentrations of about 2,000 ppm, a salinity lying far above the limit of tolerance.
Typical tensides tolerant even of extremely high total salinities and corresponding alkaline earth ion concentrations and capable of highly effective oil mobilization, are compounds of the type of carboxymethylated oxethylates, ether sulfonates and ether sulfates, as described in U.S. Pat. Nos. 4,293,428; 4,299,711, 4,485,873; as well as No. EP=B1-0 064 384. However, while the ether sulfates (cf. DOS No. 2,558,548) are considered to be not temperature-stable, the carboxymethylated oxethylates and the ether sulfonates are considered to display long-term temperature stability even under drastic conditions.
Carboxymethylated oxethylates, as tensides for tenside flooding and/or micellar tenside flooding, can be tailored to the given reservoir. As demonstrated in U.S. Pat. Nos. 4,457,373 and 4,485,873, the so-called phase inversion temperature (PIT) is the criterion for this adaptation of the tenside to the given reservoir system. If the PIT of the system of crude oil/formation water/tenside/optional additives is at the reservoir temperature or up to 10.degree. C. higher, then optimum action of the tenside can be expected with regard to oil mobilization and oil layer formation. A relatively minor deviation of the local reservoir temperature from its average value by +5.degree. C., which is quite commonplace, does not appreciably affect tenside activity. However, strong temperature gradients with temperature spans of between 10.degree. and 100.degree. C. drastically impair the effectiveness of the carboxymethylated oxethylates. This can be impressively demonstrated by measuring the interfacial surface tension of oil-aqueous tenside solution in dependence on the temperature (cf. D. Balzer, Proceedings 2nd European Symposium Enhanced Oil Recovery, Paris 1982). According thereto, the interfacial tension of the system crude oil/formation water/carboxymethylated oxethylate passes through a deep, narrow minimum at a certain temperature ordinarily lying close to the PIT. In contrast, with markedly lower or higher temperatures, for this reservoir system the tenside exhibits a very much lower interfacial activity and consequently restricted effectiveness in oil mobilization. Thus, with a carboxymethylated oxethylate utilized in connection with a reservoir system wherein the PIT is about 95.degree. C., a strong additional oil extraction in the form of an oil layer can be observed at 90.degree. C. In contrast, if the test temperature is lowered to 20.degree. C., only a small amount of residual oil--and even this amount only in the form of an oil-in-water emulsion--can be liberated.